The present invention relates to a method of estimating a petrophysical property of a subsurface area and, more particularly, to a method of estimating a petrophysical property of a subsurface area using an acoustic calibration relationship.
Acoustic data has a tremendous role in oilfield exploration and production because it is often the best way of xe2x80x9cseeingxe2x80x9d deeply into a subsurface formation. However, the data that can be readily extracted, notably compressional and shear velocities and acoustic impedences, are difficult to use for useful prediction of petrophysical properties throughout an interval. Equations such as those described in Wyllie, et al., xe2x80x9cElastic wave velocities in heterogeneous and porous mediaxe2x80x9d: Geophysics, 21, 41-70, for predicting porosity are only valid for single-mineral formations. Equations such as those in Han et al., xe2x80x9cEffects of porosity and clay content on wave velocities in sandstonesxe2x80x9d: Geophysics, 51, 2093-2105, and Tosaya et al., xe2x80x9cEffects of diagenesis and clays on compressional velocities in rocksxe2x80x9d: Geophysical Research Letters, Vol. 5, No. 1, 5-8, that predict compressional and shear velocities from clay and porosity are generally not sufficiently accurate nor robust to invert for clay and porosity from velocities.
A number of studies have been made of the parameters governing acoustic velocities in siliciclastics. The two main parameters are porosity, Ø, and clay content, C, with effective stress of lesser significance. One set of these algorithms, from Han et al., is given below:
Vp=5.59xe2x88x926.93Øxe2x88x922.18C,
Vs=3.52xe2x88x924.91Øxe2x88x921.89C.xe2x80x83xe2x80x83(1)
Klimentos, in xe2x80x9cThe effect of porosity-permeability-clay content on the velocity of compressional wavesxe2x80x9d: Geophysics, 56, 1930-1939, published a similar relationship for compressional velocity as a function of porosity and clay:
Vp=5.87xe2x88x926.99Øxe2x88x923.33C.xe2x80x83xe2x80x83(2)
The inventors have compared these prediction algorithms to measured data, and the measured and predicted curves often differ by as much or more than 1 km/sec. Other published algorithms produce a similar lack of agreement with measured velocities.
There are several possible explanations for the lack of agreement. Clay concentrations are typically determined by thin section analysis or from gamma-ray logging data and this is notoriously inaccurate. In Goldberg et al., xe2x80x9cA semi-empirical velocity-porosity-clay model for petrophysical interpretation of P- and S-velocitiesxe2x80x9d: Geophysical Prospecting, 46, 271-285, for instance, clay content was estimated from gamma-ray logging data.
It is also possible that the core samples used in the analysis do not well represent the entire sedimentary environment and additional sample measurements are required to determine if some type of global relationship could even theoretically be developed.
Previous work in this area has tended to focus on the analysis of rocks that may act as hydrocarbon reservoirs, such as sandstones, and have often overlooked the difficulties involved in determining petrophysical properties of other lithologies, such as shales.
A further problem with this prior work is that they appear to have assumed that a single correlation relationship would be sufficient to properly correlate petrophysical properties with acoustic properties over a wide range of subsurface formations.
Accordingly, it is an object of the present invention to provide an improved method of estimating a petrophysical property of a subsurface area using an acoustic calibration relationship.
An object of certain embodiments of this method is to estimate petrophysical properties away from a borehole using seismic data and an acoustic calibration relationship developed from measurements obtained near the borehole.
Further objects of certain embodiments of the inventive method include estimating porosity, clay fraction, and/or permeability of regions within a subsurface area from seismic measurements obtained from the subsurface area and an acoustic calibration relationship developed from measurements made in a nearby well or in a well from a geologically-related area.
One aspect of this invention involves a method of estimating a petrophysical property of a subsurface area including deriving an acoustic calibration relationship correlating acoustic propagation characteristics of a first subsurface area with a petrophysical property of the first subsurface area determined using nuclear spectroscopy measurements; processing acoustic data acquired from a second subsurface area to determine acoustic propagation characteristics associated with a plurality of regions within the second subsurface area; and estimating the petrophysical property of the regions within the second subsurface area using the acoustic calibration relationship and the acoustic propagation characteristics associated with the second subsurface area. Another aspect of the invention involves determining one or more boundaries within the first subsurface area, deriving different acoustic calibration relationships on opposite sides of these one or more boundaries, and then using these different acoustic calibration relationships to estimate a petrophysical property of regions within the second subsurface area. Further features and applications of the present invention will be apparent from the figures and detailed description that follows.